Systems and methods for producing oil and/or gas

ABSTRACT

A method comprising recovering a carbon source from a formation; converting at least a portion of the carbon source to a synthesis gas; converting at least a portion of the synthesis gas to an ether; and injecting at least a portion of the ether into the formation.

FIELD OF THE INVENTION

The present disclosure relates to systems and methods for producing oil and/or gas.

BACKGROUND OF THE INVENTION

Enhanced Oil Recovery (EOR) may be used to increase oil recovery in fields worldwide. There are three main types of EOR, thermal, chemical/polymer and gas injection, which may be used to increase oil recovery from a reservoir, beyond what can be achieved by conventional means—possibly extending the life of a field and boosting the oil recovery factor.

Thermal enhanced recovery works by adding heat to the reservoir. The most widely practiced form is a steam drive, which reduces oil viscosity so that it can flow to the producing wells. Chemical flooding increases recovery by reducing the capillary forces that trap residual oil. Polymer flooding improves the sweep efficiency of injected water. Miscible injection works in a similar way to chemical flooding. By injecting a fluid that is miscible with the oil, trapped residual oil can be recovered.

Referring to FIG. 1, there is illustrated prior art system 100. System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108. Production facility 110 is provided at the surface. Well 112 traverses formations 102 and 104, and terminates in formation 106. The portion of formation 106 is shown at 114. Oil and gas are produced from formation 106 through well 112, to production facility 110. Gas and liquid are separated from each other, gas is stored in gas storage 116 and liquid is stored in liquid storage 118.

U.S. Pat. No. 5,826,656 discloses a method for recovering waterflood residual oil from a waterflooded oil-bearing subterranean formation penetrated from an earth surface by at least one well by injecting an oil miscible solvent into a waterflood residual oil-bearing lower portion of the oil-bearing subterranean formation through a well completed for injection of the oil miscible solvent into the lower portion of the oil-bearing formation; continuing the injection of the oil miscible solvent into the lower portion of the oil-bearing formation for a period of time equal to at least one week; recompleting the well for production of quantities of the oil miscible solvent and quantities of waterflood residual oil from an upper portion of the oil-bearing formation; and producing quantities of the oil miscible solvent and waterflood residual oil from the upper portion of the oil-bearing formation. The formation may have previously been both waterflooded and oil miscible solvent flooded. The solvent may be injected through a horizontal well and solvent and oil may be recovered through a plurality of wells completed to produce oil and solvent from the upper portion of the oil-bearing formation. U.S. Pat. No. 5,826,656 is herein incorporated by reference in its entirety.

Co-pending U.S. Patent Application Publication Number 2006/0254769, published Nov. 16, 2006, and having attorney docket number TH2616, discloses a system including a mechanism for recovering oil and/or gas from an underground formation, the oil and/or gas comprising one or more hydrocarbons; a mechanism for converting at least a portion of the hydrocarbons from the recovered oil and/or gas into a carbon disulfide formulation; and a mechanism for releasing at least a portion of the carbon disulfide formulation into a formation. U.S. Patent Application Publication Number 2006/0254769 is herein incorporated by reference in its entirety.

Co-pending PCT Patent Application Publication Number WO 2008/141051, published Nov. 20, 2008, and having attorney docket number TH3276, discloses a system for producing oil and/or gas from an underground formation including a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation including dimethyl ether; and a mechanism to produce oil and/or gas from the formation. Co-pending PCT Patent Application Publication Number WO 2008/141051 is herein incorporated by reference in its entirety.

There is a need in the art for improved systems and methods for enhanced oil recovery. There is a further need in the art for improved systems and methods for enhanced oil recovery using a solvent, for example through viscosity reduction, chemical effects, and miscible flooding. There is a further need in the art for improved systems and methods for solvent miscible flooding.

SUMMARY OF THE INVENTION

In one aspect, the invention provides a system for producing oil and/or gas from an underground formation comprising a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation comprising an ether, the ether comprising from 2 to 20 carbons; and a mechanism to produce oil and/or gas from the formation.

In another aspect, the invention provides a method for producing oil and/or gas comprising injecting an ether formulation into a formation from a first well; and producing oil and/or gas from the formation from a second well.

In another aspect, the invention provides a method comprising recovering a carbon source from a formation; converting at least a portion of the carbon source to a synthesis gas; converting at least a portion of the synthesis gas to an ether; and injecting at least a portion of the ether into the formation.

Advantages of the invention include one or more of the following:

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a solvent.

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a fluid containing a miscible solvent.

Improved compositions and/or techniques for secondary recovery of hydrocarbons.

Improved systems and methods for enhanced oil recovery.

Improved systems and methods for enhanced oil recovery using a miscible solvent.

Improved systems and methods for enhanced oil recovery using a compound which is miscible with oil in place.

Improved systems and methods for handling produced gas.

Improved systems and methods for reducing or eliminating flaring or reinjection of produced gas.

Improved systems and methods for converting gases to liquids.

Improved systems and methods for recovering and transporting oil and gas from a formation.

Improved systems and methods for maintaining formation pressure.

Improved systems and methods for maintaining production rates.

Improved systems and methods for increasing the life of a reservoir.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an oil and/or gas production system.

FIG. 2 a illustrates a well pattern.

FIGS. 2 b and 2 c illustrate the well pattern of FIG. 2 a during enhanced oil recovery processes.

FIGS. 3 a-3 c illustrate oil and/or gas production systems.

FIG. 4 illustrates an oil and/or gas production method.

FIG. 5 illustrates an EOR agent production process.

DETAILED DESCRIPTION OF THE INVENTION

Well Spacing

Referring now to FIG. 2 a, in some embodiments, an array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

Each well in well group 202 has horizontal distance 230 from the adjacent well in well group 202. Each well in well group 202 has vertical distance 232 from the adjacent well in well group 202.

Each well in well group 204 has horizontal distance 236 from the adjacent well in well group 204. Each well in well group 204 has vertical distance 238 from the adjacent well in well group 204.

Each well in well group 202 is distance 234 from the adjacent wells in well group 204. Each well in well group 204 is distance 234 from the adjacent wells in well group 202.

In some embodiments, each well in well group 202 is surrounded by four wells in well group 204. In some embodiments, each well in well group 204 is surrounded by four wells in well group 202.

In some embodiments, horizontal distance 230 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, vertical distance 232 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, horizontal distance 236 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, vertical distance 238 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, distance 234 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, array of wells 200 may have from about 10 to about 1000 wells, for example from about 1 to about 500 wells in well group 202, and from about 1 to about 500 wells in well group 204.

In some embodiments, array of wells 200 is seen as a top view with well group 202 and well group 204 being vertical wells spaced on a piece of land. In some embodiments, array of wells 200 is seen as a cross-sectional side view with well group 202 and well group 204 being horizontal wells spaced within a formation.

Referring now to FIG. 2 b, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

In some embodiments, a miscible enhanced oil recovery agent is injected into well group 204, and oil is recovered from well group 202. As illustrated, the miscible enhanced oil recovery agent has injection profile 208, and oil recovery profile 206 is being produced to well group 202.

In some embodiments, a miscible enhanced oil recovery agent is injected into well group 202, and oil is recovered from well group 204. As illustrated, the miscible enhanced oil recovery agent has injection profile 206, and oil recovery profile 208 is being produced to well group 204.

In some embodiments, well group 202 may be used for injecting a miscible enhanced oil recovery agent, and well group 204 may be used for producing oil and/or gas from the formation for a first time period; then well group 204 may be used for injecting a miscible enhanced oil recovery agent, and well group 202 may be used for producing oil and/or gas from the formation for a second time period, where the first and second time periods comprise a cycle.

In some embodiments, multiple cycles may be conducted which include alternating well groups 202 and 204 between injecting a miscible enhanced oil recovery agent, and producing oil and/or gas from the formation, where one well group is injecting and the other is producing for a first time period, and then they are switched for a second time period.

In some embodiments, a cycle may be from about 12 hours to about 1 year, or from about 3 days to about 6 months, or from about 5 days to about 3 months. In some embodiments, each cycle may increase in time, for example each cycle may be from about 5% to about 10% longer than the previous cycle, for example about 8% longer.

In some embodiments, a miscible enhanced oil recovery agent or a mixture including a miscible enhanced oil recovery agent may be injected at the beginning of a cycle, and an immiscible enhanced oil recovery agent or a mixture including an immiscible enhanced oil recovery agent may be injected at the end of the cycle. In some embodiments, the beginning of a cycle may be the first 10% to about 80% of a cycle, or the first 20% to about 60% of a cycle, the first 25% to about 40% of a cycle, and the end may be the remainder of the cycle.

Referring now to FIG. 2 c, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

In some embodiments, a miscible enhanced oil recovery agent is injected into well group 204, and oil is recovered from well group 202. As illustrated, the miscible enhanced oil recovery agent has injection profile 208 with overlap 210 with oil recovery profile 206, which is being produced to well group 202.

In some embodiments, a miscible enhanced oil recovery agent is injected into well group 202, and oil is recovered from well group 204. As illustrated, the miscible enhanced oil recovery agent has injection profile 206 with overlap 210 with oil recovery profile 208, which is being produced to well group 204.

Enhanced Oil Recovery Methods

The recovery of oil and/or gas with array of wells 200 from an underground formation may be accomplished by any known method. Suitable methods include subsea production, surface production, primary, secondary, or tertiary production. The selection of the method used to recover the oil and/or gas from the underground formation is not critical.

In some embodiments, oil and/or gas may be recovered from a formation into a well, and flow through the well and flowline to a facility. In some embodiments, enhanced oil recovery, with the use of an agent for example steam, water, a surfactant, a polymer flood, and/or a miscible agent such as a dimethyl ether formulation, a diethyl ether formulation or carbon dioxide, may be used to increase the flow of oil and/or gas from the formation.

Releasing at least a portion of the miscible enhanced oil recovery agent and/or other liquids and/or gases may be accomplished by any known method. One suitable method is injecting the miscible enhanced oil recovery formulation into a single conduit in a single well, allowing an ether formulation to soak, and then pumping out at least a portion of the ether formulation with gas and/or liquids. Another suitable method is injecting the miscible enhanced oil recovery formulation into a first well, and pumping out at least a portion of the miscible enhanced oil recovery formulation with gas and/or liquids through a second well. The selection of the method used to inject at least a portion of the miscible enhanced oil recovery formulation and/or other liquids and/or gases is not critical.

In some embodiments, the miscible enhanced oil recovery formulation and/or other liquids and/or gases may be pumped into a formation at a pressure up to the fracture pressure of the formation.

In some embodiments, the miscible enhanced oil recovery formulation may be mixed in with oil and/or gas in a formation to form a mixture which may be recovered from a well. In some embodiments, a quantity of the miscible enhanced oil recovery formulation may be injected into a well, followed by another component to force the formulation across the formation. For example air, water in liquid or vapor form, carbon dioxide, nitrogen, alcohols, other gases, other liquids, and/or mixtures thereof may be used to force the miscible enhanced oil recovery formulation across the formation.

In some embodiments, the miscible enhanced oil recovery formulation may be heated prior to being injected into the formation to lower the viscosity of fluids in the formation, for example heavy oils, paraffins, asphaltenes, etc.

In some embodiments, the miscible enhanced oil recovery formulation may be heated and/or boiled while within the formation, with the use of a heated fluid or a heater, to lower the viscosity of fluids in the formation. In some embodiments, heated water and/or steam may be used to heat and/or vaporize the miscible enhanced oil recovery formulation in the formation.

In some embodiments, the miscible enhanced oil recovery formulation may be heated and/or boiled while within the formation, with the use of a heater. One suitable heater is disclosed in copending U.S. patent application Ser. No. 10/693,816, filed on Oct. 24, 2003, and having attorney docket number TH2557. U.S. patent application Ser. No. 10/693,816 is herein incorporated by reference in its entirety.

FIGS. 3 a-3 b:

Referring now to FIGS. 3 a and 3 b, in some embodiments of the invention, system 300 is illustrated. System 300 includes underground formation 302, underground formation 304, underground formation 306, and underground formation 308. Facility 310 is provided at the surface. Well 312 traverses formations 302 and 304, and has openings in formation 306. Portions 314 of formation 306 may be optionally fractured and/or perforated. During primary production, oil and gas from formation 306 is produced into portions 314, into well 312, and travels up to facility 310. Facility 310 then separates gas, which is sent to gas processing 316, and liquid, which is sent to liquid storage 318. Facility 310 also includes miscible enhanced oil recovery formulation storage 330. As shown in FIG. 3 a, miscible enhanced oil recovery formulation may be pumped down well 312 that is shown by the down arrow and pumped into formation 306. Miscible enhanced oil recovery formulation may be left to soak in formation for a period of time from about 1 hour to about 15 days, for example from about 5 to about 50 hours.

After the soaking period, as shown in FIG. 3 b, miscible enhanced oil recovery formulation and oil and/or gas is then produced back up well 312 to facility 310. Facility 310 is adapted to separate and/or recycle miscible enhanced oil recovery formulation, for example by boiling the formulation, condensing it or filtering or reacting it or extracting it with water, then re-injecting the formulation into well 312, for example by repeating the soaking cycle shown in FIGS. 3 a and 3 b from about 2 to about 5 times.

In some embodiments, miscible enhanced oil recovery formulation may be pumped into formation 306 below the fracture pressure of the formation, for example from about 40% to about 90% of the fracture pressure.

In some embodiments, well 312 as shown in FIG. 3 a injecting into formation 306 may be representative of a well in well group 202, and well 312 as shown in FIG. 3 b producing from formation 306 may be representative of a well in well group 204.

In some embodiments, well 312 as shown in FIG. 3 a injecting into formation 306 may be representative of a well in well group 204, and well 312 as shown in FIG. 3 b producing from formation 306 may be representative of a well in well group 202.

FIG. 3 c:

Referring now to FIG. 3 c, in some embodiments of the invention, system 400 is illustrated. System 400 includes underground formation 402, formation 404, formation 406, and formation 408. Production facility 410 is provided at the surface. Well 412 traverses formation 402 and 404 has openings at formation 406. Portions of formation 414 may be optionally fractured and/or perforated. As oil and gas is produced from formation 406 it enters portions 414, and travels up well 412 to production facility 410. Gas and liquid may be separated, and gas may be sent to gas storage 416, and liquid may be sent to liquid storage 418. Production facility 410 is able to produce and/or store miscible enhanced oil recovery formulation, which may be produced and stored in production/storage 430. Dimethyl ether, diethyl ether, and/or other ethers from well 412 may be sent to miscible enhanced oil recovery formulation production/storage 430. Miscible enhanced oil recovery formulation is pumped down well 432, to portions 434 of formation 406. Miscible enhanced oil recovery formulation traverses formation 406 to aid in the production of oil and gas, and then the miscible enhanced oil recovery formulation, oil and/or gas may all be produced to well 412, to production facility 410. Miscible enhanced oil recovery formulation may then be recycled, for example by boiling the formulation, condensing it or filtering or reacting it or extracting it with water, then re-injecting the formulation into well 432.

In some embodiments, a quantity of miscible enhanced oil recovery formulation or miscible enhanced oil recovery formulation mixed with other components may be injected into well 432, followed by another component to force miscible enhanced oil recovery formulation or miscible enhanced oil recovery formulation mixed with other components across formation 406, for example air; water in gas or liquid form; water mixed with one or more salts, polymers, and/or surfactants; carbon dioxide; nitrogen; alcohols; other gases; other liquids; and/or mixtures thereof.

In some embodiments, well 412 which is producing oil and/or gas is representative of a well in well group 202, and well 432 which is being used to inject miscible enhanced oil recovery formulation is representative of a well in well group 204.

In some embodiments, well 412 which is producing oil and/or gas is representative of a well in well group 204, and well 432 which is being used to inject miscible enhanced oil recovery formulation is representative of a well in well group 202.

FIG. 4:

Referring now to FIG. 4, in some embodiments of the invention, method 500 is illustrated. Method 500 includes injecting a miscible enhanced oil recovery formulation indicated by checkerboard pattern; injecting an immiscible enhanced oil recovery formulation indicated by diagonal pattern; and producing oil and/or gas from a formation indicated by white pattern.

Injection and production timing for well group 202 is shown by the top timeline, while injection and production timing for well group 204 is shown by the bottom timeline.

In some embodiments, at time 520, miscible enhanced oil recovery formulation is injected into well group 202 for time period 502, while oil and/or gas is produced from well group 204 for time period 503. Then, miscible enhanced oil recovery formulation is injected into well group 204 for time period 505, while oil and/or gas is produced from well group 202 for time period 504. This injection/production cycling for well groups 202 and 204 may be continued for a number of cycles, for example from about 5 to about 25 cycles.

In some embodiments, at time 530, there may be a cavity in the formation due to oil and/or gas that has been produced during time 520. During time 530, only the leading edge of cavity may be filled with a miscible enhanced oil recovery formulation, which is then pushed through the formation with an immiscible enhanced oil recovery formulation. Miscible enhanced oil recovery formulation may be injected into well group 202 for time period 506, then immiscible enhanced oil recovery formulation may be injected into well group 202 for time period 508, while oil and/or gas may be produced from well group 204 for time period 507. Then, miscible enhanced oil recovery formulation may be injected into well group 204 for time period 509, then immiscible enhanced oil recovery formulation may be injected into well group 204 for time period 511, while oil and/or gas may be produced from well group 202 for time period 510. This injection/production cycling for well groups 202 and 204 may be continued for a number of cycles, for example from about 5 to about 25 cycles.

In some embodiments, at time 540, there may be a significant hydraulic communication between well group 202 and well group 204. Miscible enhanced oil recovery formulation may be injected into well group 202 for time period 512, then immiscible enhanced oil recovery formulation may be injected into well group 202 for time period 514 while oil and/or gas may be produced from well group 204 for time period 515. The injection cycling of miscible and immiscible enhanced oil recovery formulations into well group 202 while producing oil and/or gas from well group 204 may be continued as long as desired, for example as long as oil and/or gas is produced from well group 204.

In some embodiments, periods 502, 503, 504, and/or 505 may be from about 6 hours to about 10 days, for example from about 12 hours to about 72 hours, or from about 24 hours to about 48 hours.

In some embodiments, each of periods 502, 503, 504, and/or 505 may increase in length from time 520 until time 530.

In some embodiments, each of periods 502, 503, 504, and/or 505 may continue from time 520 until time 530 for about 5 to about 25 cycles, for example from about 10 to about 15 cycles.

In some embodiments, period 506 is from about 10% to about 50% of the combined length of period 506 and period 508, for example from about 20% to about 40%, or from about 25% to about 33%.

In some embodiments, period 509 is from about 10% to about 50% of the combined length of period 509 and period 511, for example from about 20% to about 40%, or from about 25% to about 33%.

In some embodiments, the combined length of period 506 and period 508 is from about 2 days to about 21 days, for example from about 3 days to about 14 days, or from about 5 days to about 10 days.

In some embodiments, the combined length of period 509 and period 511 is from about 2 days to about 21 days, for example from about 3 days to about 14 days, or from about 5 days to about 10 days.

In some embodiments, the combined length of period 512 and period 514 is from about 2 days to about 21 days, for example from about 3 days to about 14 days, or from about 5 days to about 10 days.

In some embodiments, oil and/or gas produced may be transported to a refinery and/or a treatment facility. The oil and/or gas may be processed to produced to produce commercial products such as transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. Processing may include distilling and/or fractionally distilling the oil and/or gas to produce one or more distillate fractions. In some embodiments, the oil and/or gas, and/or the one or more distillate fractions may be subjected to a process of one or more of the following: catalytic cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming, polymerization, isomerization, alkylation, blending, and dewaxing.

Enhanced Oil Recovery Agents

In some embodiments, oil and/or gas may be recovered from a formation with methanol and/or one or more methanol derivatives, such as dimethyl ether, acetic acid, formaldehyde, and olefins, other ethers such as methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME) and the like, dimethoxy methane, polydimethoxy methane, and other chemical products produced from methanol, hereinafter referred to as a methanol compound. The methanol compound may include dimethyl ether.

In some embodiments, oil and/or gas may be recovered from a formation with nitrogen; glycols, such as mono-ethylene glycol, di-ethylene glycol, tri-ethylene glycol, and tetra-ethylene glycol; ethanol, methanol, or other alcohols; acetals; polyols; methyl isobutyl carbinol; butyl propionate, methyl acetate, ethyl acetate tertiary butyl acetate, or other esters; methyl ethyl ketone, methyl isobutyl ketone, or other ketones; and/or one or more methanol derivatives, such as dimethyl ether and dimethyl carbonate, and/or one or more ethanol derivatives, such as diethyl ether and diethyl carbonate.

In some embodiments, a hydrocarbon from the formation may be converted into a dimethyl ether formulation. The conversion of at least a portion of the hydrocarbon into a dimethyl ether formulation may be accomplished by any known method. Suitable methods may include reacting steam and natural gas at high temperatures and moderate pressures over a reduced nickel-containing catalyst so as to produce synthesis gas, where the natural gas may contain C1 to C6 compounds, such as C1 to C4 compounds. The synthesis gas production may be sent to a methanol reactor to generate methanol, which can be dehydrated to generate the dimethyl ether formulation. The selection of the method used to convert at least a portion of the hydrocarbon into a dimethyl ether formulation is not critical.

U.S. Pat. Nos. 7,168,265, 7,100,692, and 7,083,662 disclose the production of dimethyl ether from natural gas. U.S. Pat. Nos. 7,168,265, 7,100,692, and 7,083,662 are herein incorporated by reference in their entirety.

In some embodiments, a suitable miscible enhanced oil recovery agent may be a dimethyl ether formulation. The dimethyl ether formulation may include dimethyl ether and/or dimethyl ether derivatives and/or precursors for example, methanol and mixtures thereof; and optionally one or more of the following: carbon dioxide, C1-C6 hydrocarbons, water, nitrogen, and mixtures thereof.

In some embodiments, suitable miscible enhanced oil recovery agents include dimethyl ether, hydrogen sulfide, carbon dioxide, octane, pentane, LPG, C2-C6 aliphatic hydrocarbons, nitrogen, diesel, mineral spirits, naptha solvent, asphalt solvent, kerosene, acetone, xylene, trichloroethane, or mixtures of two or more of the preceding, or other miscible enhanced oil recovery agents as are known in the art. In some embodiments, suitable miscible enhanced oil recovery agents are first contact miscible or multiple contact miscible with oil in the formation.

FIG. 5:

Referring now to FIG. 5, a miscible enhanced oil recovery agent production process 600 is illustrated. Starting at 602, a carbon source is obtained. Suitable carbon sources include produced natural gas, crude oil, bitumen, oil shale, tar sands, coke, coal, and animal or vegetable fats, or other carbon sources as are known in the art. The selection of the carbon source is not critical.

At 604, the carbon source is converted to synthesis gas (syn gas), but any known method in the art. One suitable method to convert methane to syn gas is disclosed in U.S. Patent Publication Number U.S. 2004/0256116, which is herein incorporated by reference in its entirety. The selection of the method used to convert the carbon source to syn gas is not critical.

At 606, the syn gas is converted to an alcohol, for example methanol. One suitable method to convert syn gas to an alcohol is disclosed in U.S. Patent Publication Number U.S. 2004/0256116, which is herein incorporated by reference in its entirety. The selection of the method used to convert the syn gas to an alcohol is not critical.

At 608, the alcohol is converted to an ether, for example ethanol to ethyl ether, methanol to methyl ether, or a mixture of ethanol and methanol to methylethyl ether. One suitable method to convert one or more alcohols to ethers is catalytic distillation, which is disclosed in U.S. Patent Application Publication Number U.S. 2004/0204614, which is herein incorporated by reference in its entirety. Suitable methods to convert ethanol to diethyl ether are disclosed in JP63310841, JP63253043, and JP60215642, which are herein incorporated by reference in their entirety. Other suitable methods for converting alcohols to ethers are disclosed in U.S. Pat. Nos. 5,684,213, 5,750,799, and 6,740,783; U.S. Patent Application Publication Numbers 2004/0034255, 2004/0064002, 2006/0020155, 2006/0135823, 2006/0224012, 2007/0066855, and 2007/0078285; and International Publication Numbers WO 2006/041253, and 2008/026887; which are all herein incorporated by reference in their entirety. The selection of the method used to convert the alcohol to an ether is not critical.

At 610, the ether is injected into a formation to aid in the recovery of oil and/or gas. Suitable methods to inject liquids and gases are disclosed above and are known in the art. The selection of the method used to inject the ether is not critical.

In some embodiments, 606 and 608 can be combined where the syngas is converted an ether in a single process. Suitable methods for converting syn gas to ethers are disclosed in U.S. Pat. Nos. 5,218,003, 5,908,963, 6,069,180, 6,191,175, and 6,458,856; U.S. Patent Application Publication Numbers 2005/0038129, 2006/0020155, and 2007/0078285; International Publication Number WO 99/21814; European Patent Application Numbers 0 324 475, 0 409 086, 0 483 609; and UK Patent Application Number 2 253 623; which are all herein incorporated by reference in their entirety. The selection of the method used to convert the syngas to an ether is not critical.

In some embodiments, process 600 may have an input of produced natural gas, crude oil, or other carbon sources from a local formation, for example the same formation that the ether will be injected into.

In some embodiments, process 600 may skip steps 602 and 604, and may have an input of ethanol, produced from corn, sugar cane, cellulose, or other sugar sources as are known in the art.

In some embodiments, suitable ethers produced at 608 include ethers having from about 2 to about 20 carbons, for example from about 3 to about 10, or from about 4 to about 8 carbons. Suitable ethers include dimethyl ether, methyl-ethyl ether, diethyl ether, dipropyl ether, methyl-propyl ether, ethyl-propyl ether (primary or secondary), dibutyl ether (primary or secondary or tertiary), diamyl ether, tertiary-amyl methyl ether (TAME), ethyl tertiary butyl ether (ETBE), methyl tertiary-butyl ether (MTBE) and other ethers as are known in the art having from about 2 to about 20 carbons.

In some embodiments, process step 608 may produce ethers and one or more byproducts such as alcohols, water, carbon dioxide, nitrogen, and possibly other liquids and/or gases. These byproducts may also be injected in a mixture with the ether, or as an immiscible enhanced oil recovery agents to push the ether through the formation.

In some embodiments, suitable immiscible enhanced oil recovery agents include water in gas or liquid form, air, nitrogen, mixtures of two or more of the preceding, or other immiscible enhanced oil recovery agents as are known in the art. In some embodiments, suitable immiscible enhanced oil recovery agents are not first contact miscible or multiple contact miscible with oil in the formation.

In some embodiments, immiscible and/or miscible enhanced oil recovery agents injected into the formation may be recovered from the produced oil and/or gas and re-injected into the formation.

In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of at least about 0.01 centipoise, or at least about 0.1 centipoise, or at least about 0.5 centipoise, or at least about 1 centipoise, or at least about 2 centipoise, or at least about 5 centipoise. In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of up to about 500 centipoise, or up to about 100 centipoise, or up to about 50 centipoise, or up to about 25,000 centipoise.

Illustrative Embodiments

In one embodiment of the invention, there is disclosed a system for producing oil and/or gas from an underground formation comprising a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation comprising an ether, the ether comprising from 2 to 20 carbons; and a mechanism to produce oil and/or gas from the formation. In some embodiments, the system also includes a second well a distance from the first well, wherein the mechanism to produce oil and/or gas from the formation is located at the second well. In some embodiments, the mechanism to inject is located at the well, and wherein the mechanism to produce oil and/or gas from the formation is located at the well. In some embodiments, the underground formation is beneath a body of water. In some embodiments, the system also includes a mechanism for injecting an immiscible enhanced oil recovery formulation into the formation, after the enhanced oil recovery formulation has been released into the formation. In some embodiments, the enhanced oil recovery formulation further comprises one or more of hydrogen sulfide, carbon disulfide, carbon dioxide, carbon monoxide, octane, pentane, LPG, propane, C2-C6 aliphatic hydrocarbons, nitrogen, diesel, mineral spirits, naptha solvent, asphalt solvent, kerosene, acetone, xylene, trichloroethane, acetals, glycols, polyols, esters, ketones, aldols, alcohols, ammonia, amines, and mixtures thereof. In some embodiments, the system also includes an immiscible enhanced oil recovery formulation selected from the group consisting of water in gas or liquid form, air, nitrogen, methane, and mixtures thereof. In some embodiments, the well comprises an array of wells from 5 to 500 wells. In some embodiments, the mechanism to produce oil and/or gas from the formation is located at the well. In some embodiments, the system also includes a mechanism for producing a carbon source from the formation. In some embodiments, the system also includes a mechanism to produce a synthesis gas from the carbon source. In some embodiments, the system also includes a mechanism to produce the ether from the synthesis gas, either directly or with an alcohol intermediate. In some embodiments, the system also includes a mechanism for producing the ether adjacent to the well.

In one embodiment of the invention, there is disclosed a method for producing oil and/or gas comprising injecting an ether formulation into a formation from a first well; and producing oil and/or gas from the formation from a second well. In some embodiments, the method also includes recovering the ether formulation from the oil and/or gas, if present, and then injecting at least a portion of the recovered ether formulation into the formation. In some embodiments, injecting the ether formulation comprises injecting at least a portion of the ether formulation into the formation in a mixture with one or more of hydrocarbons other than the ether; carbon dioxide; carbon monoxide; nitrogen; or mixtures thereof. In some embodiments, injecting the ether formulation comprises injecting at least a portion of the ether formulation into the formation in a mixture, wherein the mixture comprises from 5% to 90% ether by weight. In some embodiments, the method also includes heating the ether formulation prior to injecting the ether formulation into the formation, or while within the formation. In some embodiments, the ether formulation is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when ether injection begins. In some embodiments, the ether formulation is injected into a reservoir having a reservoir temperature of at least 100 degrees centigrade, for example at least 250 degrees centigrade, measured prior to when ether injection begins. In some embodiments, the underground formation comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy. In some embodiments, the method also includes converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. In some embodiments, the method also includes converting at least a portion of the recovered oil and/or gas into an ether, and injecting the ether into an underground formation. In some embodiments, the method also includes recovering an ether formulation from the oil and/or gas, if present, and then transporting the ether formulation to another location, for example by a pipeline, a vessel, a pressurized vessel, or a chilled vessel. In some embodiments, the method also includes converting at least a portion of the recovered oil and/or gas into an ether, and then transporting the ether formulation to another location, for example by a pipeline, a vessel, a pressurized vessel, or a chilled vessel. In some embodiments, the underground formation comprises an oil having an API from 10 to 100. In some embodiments, injecting the ether formulation comprises injecting a mixture of the ether formulation and water. In some embodiments, the water further comprises a water soluble polymer adapted to increase a viscosity of the mixture. In some embodiments, the method also includes producing the ether formulation on an offshore structure from a starting material comprising synthesis gas, methanol, or mixtures thereof. In some embodiments, the method also includes reducing a bubble point of the oil in the formation with the ether formulation. In some embodiments, the method also includes increasing a swelling factor of the oil in the formation with the ether formulation. In some embodiments, the method also includes reducing a viscosity of the oil in the formation with the ether formulation.

In one embodiment of the invention, there is disclosed a method comprising recovering a carbon source from a formation; converting at least a portion of the carbon source to a synthesis gas; converting at least a portion of the synthesis gas to an ether; and injecting at least a portion of the ether into the formation.

Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments of the invention, configurations, materials and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature. 

1. A system for producing oil and/or gas from an underground formation comprising: a well above the formation; a mechanism to inject an enhanced oil recovery formulation into the formation, the enhanced oil recovery formulation comprising an ether, the ether comprising from 2 to 20 carbons; and a mechanism to produce oil and/or gas from the formation.
 2. The system of claim 1, further comprising a second well a distance from the first well, wherein the mechanism to produce oil and/or gas from the formation is located at the second well.
 3. The system of claim 1, wherein the mechanism to inject is located at the well, and wherein the mechanism to produce oil and/or gas from the formation is located at the well.
 4. The system of claim 1, wherein the underground formation is beneath a body of water.
 5. The system of claim 1, further comprising a mechanism for injecting an immiscible enhanced oil recovery formulation into the formation, after the enhanced oil recovery formulation has been released into the formation.
 6. The system of claim 1, wherein the enhanced oil recovery formulation further comprises one or more of hydrogen sulfide, carbon disulfide, carbon dioxide, carbon monoxide, octane, pentane, LPG, propane, C2-C6 aliphatic hydrocarbons, nitrogen, diesel, mineral spirits, naphtha solvent, asphalt solvent, kerosene, acetone, xylene, trichloroethane, acetals, glycols, polyols, esters, ketones, aldols, alcohols, ammonias, and mixtures thereof.
 7. The system of claim 1, further comprising an immiscible enhanced oil recovery formulation selected from the group consisting of water in gas or liquid form, air, nitrogen, methane, and mixtures thereof.
 8. The system of claim 1, wherein the well comprises an array of wells from 1 to 500 wells.
 9. The system of claim 1, wherein the mechanism to produce oil and/or gas from the formation is located at the well.
 10. The system of claim 1, further comprising a mechanism for producing a carbon source from the formation.
 11. The system of claim 10, further comprising a mechanism to produce a synthesis gas from the carbon source.
 12. The system of claim 11, further comprising a mechanism to produce the ether from the synthesis gas, either directly or with an alcohol intermediate.
 13. The system of claim 1, further comprising a mechanism for producing the ether adjacent to the well.
 14. A method for producing oil and/or gas comprising: injecting an ether formulation into a formation from a first well; and producing oil and/or gas from the formation from a second well.
 15. The method of claim 14, further comprising recovering the ether formulation from the oil and/or gas, if present, and then injecting at least a portion of the recovered ether formulation into the formation.
 16. The method of claim 14, wherein injecting the ether formulation comprises injecting at least a portion of the ether formulation into the formation in a mixture with one or more of hydrocarbons other than the ether; carbon dioxide; carbon monoxide; nitrogen; or mixtures thereof.
 17. The method of one claim 14, wherein injecting the ether formulation comprises injecting at least a portion of the ether formulation into the formation in a mixture, wherein the mixture comprises from 5% to 90% ether by weight.
 18. The method of claim 14, further comprising heating the ether formulation prior to injecting the ether formulation into the formation, or while within the formation.
 19. The method of claim 14, wherein the ether formulation is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when ether injection begins.
 20. The method of claim 14, wherein the ether formulation is injected into a reservoir having a reservoir temperature of at least 100 degrees centigrade, for example at least 250 degrees centigrade, measured prior to when ether injection begins.
 21. The method of claim 14, wherein the underground formation comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy.
 22. The method of one claim 14, further comprising converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.
 23. The method claim 14, further comprising converting at least a portion of the recovered oil and/or gas into an ether, and injecting the ether into an underground formation.
 24. The method of claim 14, further comprising recovering an ether formulation from the oil and/or gas, if present, and then transporting the ether formulation to another location, for example by a pipeline, a vessel, a pressurized vessel, or a chilled vessel.
 25. The method of claim 14, further comprising converting at least a portion of the recovered oil and/or gas into an ether, and then transporting the ether formulation to another location, for example by a pipeline, a vessel, a pressurized vessel, or a chilled vessel.
 26. The method of claim 14, wherein the underground formation comprises an oil having an API from 10 to
 100. 27. The method of claim 14, wherein injecting the ether formulation comprises injecting a mixture of the ether formulation and water.
 28. The method of claim 27, wherein the water further comprises a water soluble polymer adapted to increase a viscosity of the mixture.
 29. The method of claim 14, further comprising producing the ether formulation on an offshore structure from a starting material comprising synthesis gas, methanol, or mixtures thereof.
 30. The method of claim 14, further comprising reducing a bubble point of the oil in the formation with the ether formulation.
 31. The method of claim 14, further comprising increasing the swelling of the oil in the formation with the ether formulation.
 32. The method of claim 14, further comprising reducing the viscosity of the oil in the formation with the ether formulation.
 33. A method comprising: recovering a carbon source from a formation; converting at least a portion of the carbon source to a synthesis gas; converting at least a portion of the synthesis gas to an ether; and injecting at least a portion of the ether into the formation.
 34. The method of claim 33, further comprising converting the ether to a material selected from the group consisting of glycols, such as mono-ethylene glycol, di-ethylene glycol, tri-ethylene glycol, and tetra-ethylene glycol; ethanol, methanol, or other alcohols; acetals; polyols; methyl isobutyl carbinol; butyl propionate, methyl acetate, ethyl acetate tertiary butyl acetate, or other esters; methyl ethyl ketone, methyl isobutyl ketone, or other ketones; and/or one or more methanol derivatives, such as dimethyl carbonate, and/or one or more ethanol derivatives, such as diethyl carbonate. 